1. Field
The present invention relates to the field of drill bits. More specifically, the present invention relates to fixed-cutter, rotary-type bits for use in the drilling of subsurface wells.
2. Background
Fixed-cutter, rotary-type bits are known in the field of subsurface drilling. Such drill bits are typically comprised of a bit body having a shank for connection to a drill string. The bit body is typically cast and/or machined from a metal material, such as steel. Alternatively, the bit body may be formed of a powdered metal such as tungsten carbide infiltrated at high temperatures with a liquefied binder material to form a matrix. In either instance, the shank encompasses an inner channel for supplying drilling fluid to the face of the bit through nozzles or other openings.
Different designs and types of fixed-cutter, rotary bits are employed by the drilling industry. Two common types of fixed-cutter bits are diamond impregnated bits and polycrystalline diamond compact (“PDC”) bits. A diamond impregnated drill bit uses particulate diamonds, or “diamond grit,” impregnated in a supporting metal matrix. In the drilling process the diamond particles cut the rock. A PDC bit uses PDC cutters to shear rock with a scraping motion. In either instance, the bit body is usually divided into blades, with cutting elements being mounted onto the individual blades.
In use, the drill bit is mounted onto the lower end of a drill string. The drill bit is rotated either by rotating the drill string at the surface, or by the actuation of downhole motors or turbines. In some instances, both methods may be used. During rotation of the drill bit, weight is applied to the bit. As the bit rotates with applied weight (referred to as “weight-on-bit,” or “WOB”), the cutting elements are pressed against the formation. The rotating drill bit engages the rock formation and proceeds to form a borehole along a predetermined path toward a target zone.
The spaces formed between the drill blades are normally referred to as “junk slots.” Drilling fluid passes through the inter-blade space, or junk slots, and carries the rock chips generated during drilling up the wellbore.
In brittle formations, the chips break into small pieces which are easily transported by the drilling fluid up the wellbore. However, in plastic formations, such as shales or highly pressurized mudstones and siltstones, the chips tend to adhere to each other and to the bit surface. These cuttings may form long ribbons of reconstituted material which are difficult to remove. In addition, the cutting ribbons lead to packing of the junk slots, resulting in a condition sometimes referred to as “bit balling”. Bit balling leads to inefficient operation of the bit since the cutting structure of the bit is covered with previously drilled material. In addition, packing off of the junk slots prevents efficient transport of the cuttings out of the hole.
Of particular concern, cuttings generated while drilling shale formations with PDC bits and water-based mud have a tendency to form long ribbons of connected lamellae. These cutting ribbons lead to packing of the bit junk slots and bit balling. In some severe cases, the drill bit has to be pulled out of the hole and cleaned.
The problem of bit balling has been recognized by the industry. Various approaches have been attempted to mitigate the problem and promote the removal of cuttings. Generally, the approaches can be divided into two groups: hydraulic and mechanical.
Various patents have been issued addressing the hydraulic removal of formation cuttings. These include U.S. Pat. No. 4,606,418; U.S. Pat. No. 4,852,671; U.S. Pat. No. 5,172,778; U.S. Pat. No. 4,883,132; U.S. Pat. No. 4,913,244; GB Patent No. 2,085,945; and U.S. Pat. No. 5,115,873. These patents generally employ fluid discharge ports or fluid passages strategically placed in or between the cutter elements. The ports or passages allow the drilling fluid to cool the cutting elements and to remove the generated rock cuttings as the drilling fluid is circulated down the drill string and back up the annulus.
Various patents have also been issued addressing mechanical means for preventing cuttings accumulation, and facilitating the removal of any accumulated cuttings. These include U.S. Pat. No. 4,984,642; GB Patent No. 2,361,018; U.S. Pat. No. 5,582,258; and U.S. Pat. No. 5,447,208. U.S. Pat. No. 4,984,642 describes PDC cutters with surface corrugations for promoting chip break-up. GB Patent No. 2,361,018 discloses protrusions in the junk slots of the bit that act as chip breakers. U.S. Pat. No. 5,582,258 describes a chip breaking mechanism that imparts strain on the chip by bending and/or twisting the chip. U.S. Pat. No. 5,447,208 employs polished PDC cutting elements to provide a low-friction planar surface to reduce chip adhesion.
U.S. Pat. Nos. 5,651,420 and 5,901,797 are related patents that are directed to mechanical means attempting to reduce cuttings accumulations. These two patents provide mechanical flails disposed on various surfaces of the drill bit. The flails are tethered to the bit and some are driven by nozzles directing streams of drilling fluid in the direction of the flails. In some implementations, it is believed that these mechanical flails would become surrounded and effectively immobilized by the cuttings accumulating and balling around the flails themselves. Additionally, these patents describe bits having movable structures in an internal cavity. The drill bits are designed such that the cuttings pass through the internal cavity and are contacted by the driven structures in this internal cavity. While not clear from the descriptions of these patents, it is believed that the cavities are internal to the drill bit, such as in the axial region of the drill bit, as compared to the junk slots that are external to the bit body and disposed between the blades. It appears that this solution to bit balling in the junk slots attempted to open a portion of the junk slots to an internal cavity in which rotating vanes were believed to break the cuttings and send the broken cuttings back out of the cavity to flow through the wellbore annulus to the surface. The fluid flow of the drilling fluids and the cuttings into and out of the cavity is not made clear in the description of these patents but is believed to require a tortuous path, which is believed to introduce greater opportunities for accumulation of cuttings. These patents appear to rely upon the tethered flails to prevent such accumulations, but with the increased contacts with bit surfaces and edges, the effectiveness of such flails is questioned.
A need exists for an improved fixed cutter, rotary-type drill bit design.